Oil and gas hydrocarbons are naturally occurring in some subterranean formations. A subterranean formation containing oil or gas is sometimes referred to as a reservoir. A reservoir may be located under land or off shore. Oil and gas reservoirs are typically located in the range of a few hundred feet (shallow reservoirs) to a few tens of thousands of feet (ultra-deep reservoirs). In order to produce oil or gas, a well is drilled into a subterranean formation.
In order to produce oil or gas, a well is drilled into a subterranean formation, which may be a reservoir or adjacent to a reservoir. As used herein, a “well” includes at least one wellbore drilled into a subterranean formation, which may be a reservoir or adjacent to a reservoir. A wellbore can have vertical and horizontal portions, and it can be straight, curved, or branched. As used herein, a “well” also includes the near-wellbore region. As used herein, “into a well” means and includes into any portion of the well, including into the wellbore or into the near-wellbore region via the wellbore.
Various types of treatments are commonly performed on a well or subterranean formation. For example, stimulation is a type of treatment performed on a well or subterranean formation to restore or enhance the productivity of oil and gas from the well or subterranean formation. Stimulation treatments fall into two main groups; hydraulic fracturing and matrix treatments. Fracturing treatments are performed above the fracture pressure of the subterranean formation to create or extend a highly-permeable flow path between the formation and the wellbore. Other types of treatments include, for example, controlling excessive water production.
A treatment typically involves introducing a treatment fluid into a well. As used herein, a “treatment fluid” is a fluid used to resolve a specific condition of a wellbore or subterranean formation. As used herein, a “treatment fluid” also means the specific composition of a fluid at the time the fluid is being introduced into a wellbore. A treatment fluid is typically adapted to be used to achieve a specific purpose, such as stimulation, isolation, or control of reservoir gas or water. The word “treatment” in the term “treatment fluid” does not necessarily imply any particular action by the fluid.
As used herein, a fluid can be homogeneous or heterogeneous. A homogeneous fluid consists of a single phase (e.g. a brine or a solution of dissolved chemicals.) An example of a heterogeneous fluid is a dispersion. A dispersion is system in which one phase is dispersed in another phase. An example of a dispersion is a suspension of insoluble particles in a liquid phase. Another example of a dispersion is an emulsion. Further, a treatment fluid can include a gas for foaming the fluid. As used herein, an “aqueous” fluid is a fluid that is either a homogeneous solution comprising water or a heterogeneous fluid wherein the external phase comprises water.
“Hydraulic fracturing,” sometimes simply referred to as “fracturing,” is a common stimulation treatment. A treatment fluid adapted for this purpose is sometimes referred to as a “fracturing fluid.” The fracturing fluid is pumped at a sufficiently high flow rate and pressure into the wellbore and into the subterranean formation to create or enhance a fracture in the subterranean formation. Creating a fracture means making a new fracture in the formation. Enhancing a fracture means enlarging a pre-existing fracture in the formation.
A newly-created or extended fracture will tend to close together after the pumping of the fracturing fluid is stopped. To prevent the fracture from closing, a material must be placed in the fracture to keep the fracture propped open. A material used for this purpose is referred to as a “proppant.”
The proppant is in the form of a solid particulate, which can be suspended in the fracturing fluid, carried downhole, and deposited in the fracture as a “proppant pack.” The proppant pack props the fracture in an open condition while allowing fluid flow through the permeability of the pack. A particulate for use as a proppant is selected based on the characteristics of size range, crush strength, and insolubility.
The proppant pack in the fracture provides a higher-permeability flow path for the oil or gas to reach the wellbore compared to the permeability of the surrounding subterranean formation. This flow path increases oil and gas production from the subterranean formation.
The concentration of proppant in the treatment fluid is preferably in the range of from about 0.03 kilograms to about 3 kilograms of proppant per liter of liquid phase (0.25 lb/gal-25 lb/gal).
The proppant typically has a much different density than water. For example, water has a specific gravity of 1.0 and sand has a specific gravity of about 2.7. A different-density proppant contained in water will tend to separate from the water very rapidly. Increasing the viscosity of the water using a viscosity-increasing agent can help prevent the proppant from quickly separating out of the fluid. A viscosity-increasing agent is sometimes known in the art as a “thickener” or a “suspending agent.”
For reference, the viscosity of water is about 1 cP. As used herein, a fluid is considered to be pumpable if it has a viscosity of less than 5,000 cP.
Because of the high volume of fracturing fluid typically used in a fracturing operation, it is desirable to efficiently increase the viscosity of fracturing fluids to the desired viscosity using as little viscosity-increasing agent as possible. Being able to use only a small concentration of the viscosity-increasing agent requires a lesser amount of the viscosity-increasing agent in order to achieve the desired fluid viscosity in a large volume of fracturing fluid. Efficient and inexpensive viscosity-increasing agents include water-soluble polymers. Typical water-soluble polymers used in well treatments are water-soluble polysaccharides. The most common water-soluble polysaccharide employed in well treatments is guar and its derivatives.
The viscosity of a fluid at a given concentration of viscosity-increasing agent can be greatly increased by cross-linking the viscosity-increasing agent. A cross-linking agent, sometimes referred to as a crosslinker, can be used for this purpose. One example of a cross-linking agent is the borate ion. Gel formation is based on a number of factors including the particular polymer and concentration thereof, the particular cross-linker and concentration thereof, the degree of crosslinking, temperature, and a variety of other factors known to those of ordinary skill in the art. A “base gel” is a fluid that includes a viscosity-increasing agent, such as guar, but that excludes cross-linking agents. Typically, a base gel is a fluid that is mixed with another fluid containing a crosslinker, wherein the mixed fluid is adapted to form a gel at a desired time in a well treatment.
Optionally, one or more other additives can be included to form a treatment fluid. For example, treatment fluids used in the invention also commonly include a “breaker.” A breaker is a chemical used for the purpose of “breaking” the polymeric viscosifying agent, thus diminishing the viscosity of a fluid so that the fluid can be recovered more easily from the formation. Breakers reduce the molecular weight of the viscosity-increasing agent (which may be cross-linked) by the action of an acid, an oxidizer, an enzyme, or a combination of these. The acids, oxidizers, or enzymes can be in the form of delayed-release or encapsulated breakers.
In the case of a cross-linked viscosity-increasing agent, one way to diminish the viscosity is by breaking the cross-links. For example, the borate cross-links in a borate-crosslinked gel can be broken by lowering the pH of the fluid. At a pH above 8, the borate ion exists and is available to cross-link and cause gelling. At a lower pH, the borate is tied up by hydrogen and is not available for cross-linking, thus, an increase in viscosity due to borate cross-linking is reversible.
There are other uses for a water-soluble polysaccharide in a well treatment fluid. For example, during the drilling, completion, and stimulation of subterranean a well, it is common to pump an aqueous treatment fluid through tubular goods (e.g., pipes, coiled tubing, etc.) and into a subterranean formation adjacent a wellbore. A considerable amount of energy may be lost due to friction of the aqueous treatment fluid in turbulent flow through the tubular goods of the wellbore. As a result of these energy losses, additional pumping horsepower may be necessary to achieve the desired well treatment. To reduce these energy losses, a water-soluble polysaccharide may be included in aqueous treatment fluids. The use of an appropriate water-soluble polysaccharide as a friction reducer in a treatment fluid is expected to reduce the energy losses due to friction.
For example, in a “high-rate water fracturing treatment,” proppant suspension in the treatment fluid is largely achieved by the high rate of pumping and the high flow rate of the treatment fluid. To reduce energy losses due to friction, a water-soluble polysaccharide as a friction reducer may be included in the fracturing fluid. While a fluid used in high-rate water fracturing may contain a water-soluble polysaccharide as a friction-reducing polymer, the polysaccharide is usually included in the fracturing fluid in an amount that is sufficient to provide the desired friction reduction without forming a gel and usually without a crosslinker. As a result, the fracturing fluids used in these high-rate water fracturing operations generally have a lower viscosity than conventional fracturing fluids.
Treatment fluids used in the invention can further contain other additives that are known to be commonly used in oil field applications by those skilled in the art. These include, but are not necessarily limited to inorganic water-soluble salts breaker aids, surfactants, oxygen scavengers, alcohols, scale inhibitors, corrosion inhibitors, fluid-loss additives, oxidizers, and bactericides.
In the context of such uses for a water-soluble polysaccharide in a well treatment fluid and an associate well treatment method, the water-soluble polysaccharide has conventionally been provided as oil-external dispersion. The fluid currently used as a carrier fluid is a hydrocarbon, for example, diesel or a more environmentally-benign solvent such as alpha-olefins or saturated paraffin. The purpose of these is to suspend the water-soluble polysaccharide, such as guar. Upon mixing the dispersion with at least water to form an aqueous treatment fluid, the dispersion should invert, thereby releasing the polysaccharide into the aqueous phase.
However, the delivery of water-soluble polysaccharides for use in well treatment fluids and methods has proved challenging from an environment standpoint. The hydrocarbon carrier fluid present in the oil-external dispersion may pose environmental problems with the subsequent disposal of the treatment fluid. Among other reasons, disposal of hydrocarbons (e.g., such as the carrier fluid in the oil-external dispersion) may have undesirable environmental characteristics or may be limited by strict environmental regulations in certain areas of the world. Furthermore, the hydrocarbon carrier fluid present in the oil-external dispersion may be perceived to contaminate water in the formation.